Tubing inserted balance pump

ABSTRACT

Pump assemblies for use with a subsurface fluid reservoir include an upper barrel connected to a fluid filled conduit extending to the surface, a lower barrel connected to the upper barrel and in fluid communication with the reservoir, and a plunger assembly movably located within the upper and lower barrels. As the fluid pressure within production tubing, external to the pump assembly, increases, movement of the plunger draws fluid into the pump. As the fluid pressure within the production tubing decreases, the plunger pushes fluid into the production tubing.

FIELD

Embodiments usable within the scope of the present disclosure relate,generally, to systems and methods usable in subsurface pumps forremoving fluids (e.g., hydrocarbons) from subterranean reservoirs, andmore particularly, to rodless pumping systems and methods.

BACKGROUND

Presently, low pressure reservoirs, incapable of producing fluid fromthe reservoir to the surface naturally, account for a majority of thehydrocarbon producing wells in the United States. There are variousmeans of pumping fluid from these wells, such as the use of sucker rodpumps, hydraulic pumps, jet pumps, and semi-submersible electric pumps.Most of these depleted wells produce fluid at pressure and flow ratestoo low for the majority of existing pumps to operate efficiently and/oreconomically.

The most common method used for producing these low pressure, low flowrate wells is the use of sucker rod pumping systems. Sucker rod pumpingsystems include a downhole plunger and cylinder type pump, connected toa surface unit (e.g., a pump jack) by connecting rods (e.g., suckerrods). Existing sucker rod systems include multiple limitations anddifficulties inherent in their use. While the stroke length of the pumpand the stroke frequency may be controlled through the selection of thepump jack size, pumping jacks are too costly, and each pump size islimited to a specific range of flow rates and depth of the reservoir.Once a pump unit is placed, it is cost prohibitive to change the pumpjack, thus modification of stroke length and/or frequency is oftenimpossible. Another large problem with conventional sucker rod systemsrelates to the sucker rods, themselves. Sucker rods include segments ofmetal or fiberglass rod which are connected together to form acontinuous string of rods, normally several thousand feet in length whenused in hydrocarbon wells. These rod strings are typically connectedusing pin and box connections (e.g., threaded connections). The processof connecting the rod string when running sucker rod segments into awellbore, or disconnecting the string when removing rod segments fromthe wellbore, is time consuming and costly. Additionally, the length andweight of these rods and the repeated reciprocation of the rods causedby the pump jack often results in failure, commonly by parting of thesucker rod string. Another difficulty associated with the use of suckerrod strings is the position of the rod string within a tubing string(e.g., production tubing). When the system is operating, it is commonfor the rod string to contact the inner wall of the tubular string atvarious points, which results in wear of both the rod string and thetubular string, and can eventually cause failure of the well tubingstring, as well as the rod string. Depending of the severity of thewellbore conditions, rod pumping systems fail on the average of once amonth, quarterly, or semiannually, requiring significant repair andmaintenance costs. The frequency and expense of necessary repairs andmaintenance is often a significant factor that causes production of awell to become uneconomical. Failure rates in rod pumping systems aresignificantly more common in deviated and/or non-vertical wellbores.

There have been attempts to develop a pumping system which utilizes aplunger/cylinder-type downhole pump while eliminating the use of suckerrods, thereby eliminating the problems inherent in the use of suckerrods. Existing rodless pump systems typically include a surface unit,which is connected to a subsurface pump by a fluid conduit, such as thetubing string. The surface unit activates the subsurface pump byapplying pressure to the fluid in the tubing string to compress a springor similar member in the subsurface pump and displace a slidable piston,which thereby draws fluid from the wellbore into a pump chamber. Whenthe surface unit releases the fluid pressure, a spring mechanism in thesubsurface pump will displace the piston and lift the fluid from thepump chamber into the tubing string and toward the surface. Although,such systems eliminate use of a sucker rod string, they require acompression spring for lifting the produced fluid into the tubingstring. Use of such a spring severely limits the stroke length and thus,the flow rate of the pump. Further, springs used in this manner tend tofail due to wear and/or the accumulation of debris carried into thepump.

Other existing rodless pumps replace the physical spring with a gaschamber. When pressure is applied to the tubing string, a piston willcompress the gas within the chamber, and when the pressure is relieved,the gas will expand to lift fluid into the tubing string. These systemsallow for a longer stroke length and thus much higher efficiency, butintroduce additional problems. A major problem inherent in the use ofrodless pumps is that unlike sucker rod pumps, a rodless pump does nothave a precisely defined stroke length. In a rodless pump, the strokelength is affected by the length of time the surface unit appliespressure to the fluid in the tubing string during each cycle, by thecompressibility of the fluid in the tubing string, and by the amount ofballooning of the tubing that occurs. The stroke length is alsoinfluenced by the pressure in the gas chamber, since the pressure in thegas chamber must be sufficient to support the hydrostatic pressure ofthe entire column of fluid extending to the surface. At the end of eachdownstroke, enough force is applied to the plunger to cause the plungerto strike the bottom of the barrel with a significant impact, causingexcessive wear and potential damage. Also, because the surface unit isunable to stop applying pressure to the tubing at the precise momentnecessary to prevent this contact, the plunger will also impact thelimit stop at the end of each upstroke. Thus, unlike sucker rod pumps,rodless pumps are difficult to design in a manner that enables themaximum stroke to be utilized without the plunger contacting the barrelat the end of the upstroke and downstroke, severely limiting the usablelife of such pumps.

Other rodless pumps attempt to overcome these severe plunger impactsthrough use of dampening mechanisms, such as elastomer barriers,springs, and/or other types of dampeners, at both the top and bottom ofthe plunger's stroke. However, such rodless pump systems still utilize adownhole gas source within the pump to force the plunger assemblydownward after the surface pressure source releases the pressure beingexerted on the downhole pump. The gas pressure source requires asubstantially self-contained pressure chamber, which can be part of thepump, can be positioned downhole, and can be used to contain asubstantially compressible fluid. The chamber is also preferablyprecharged with a gas, such as nitrogen. Although this arrangement is animprovement over preceding pumps, particularly those subject to plungerimpact, it still possesses inherent limitations. For example, thisarrangement of pump requires a very high precharge pressure in the gaschamber, suffers from a short piston life due to fluid leakage andcontamination, and requires bleeding the substantial gas chamberpressure whenever retrieving the pump to the surface.

Embodiments usable within the scope of the present disclosure improveupon these and other existing designs by eliminating use of rods, pumpjacks, springs, and downhole gas sources or gas pressure chambers withinthe pump.

Another limitation associated with existing pumps is the use of ahousing structure, which surrounds sections of the pump, as a means ofengagement. To install such a pump, the production tubing string must beextracted from the well, such that the pump can be connected at the endof the tubing (e.g., via threading the housing to the tubing). The pumpis then lowered into the well by lowering the tubing string. Thisundertaking requires a significant quantity of manual labor and welldowntime, resulting in significant costs and losses of revenues.Furthermore, most repairs to these types of pumps also require theextraction of the entire tubular string to access the pump, whichrequires a major rig to handle the weight.

Embodiments usable within the scope of the present disclosure improveupon these and other existing designs by eliminating the use of widehousing, thereby enabling insertion and extraction of the pump fromand/or through production tubing without requiring extraction of theproduction tubing itself.

However, pumps that do not contain a housing structure and are insertedinto existing production tubing can be faced with certain problems.Because such pumps have small barrel and plunger diameters, they arenormally capable of moving only small volumes of produced hydrocarbonswith each stroke. One system that can overcome this limitation is asystem that includes a pump with an increased stroke length. Pumpshaving longer stroke lengths, however, can be encumbered with problems,such as piston rod buckling, ineffective sealing between the pistons andthe pump barrel, and significant barrel strains due to deep wellpressures. Embodiments usable within the scope of the present disclosureimprove upon existing systems and methods of use.

BRIEF DESCRIPTION OF THE DRAWINGS

In the detailed description of various embodiments usable within thescope of the present disclosure, presented below, reference is made tothe accompanying drawings, in which:

FIG. 1 is a cross-sectional conceptual view of an embodiment of a pumpusable within the scope of the present disclosure as it is positionedwithin the production tubing and the well bore, with the plungerassembly at the lowest position of a pump stroke

FIG. 2 is a cross-sectional close-up view of the upper plunger assemblyof the pump of FIG. 1.

FIG. 3 is a cross-sectional close-up view of the upper plunger assemblyand the mounting section of the pump of FIG. 1.

FIG. 4 is a cross-sectional view of the pump of FIG. 1, with the plungerassembly moving in the upwell direction in response to the applicationof pressure from a surface pumping unit to the fluid in the tubingstring.

FIG. 5 is a cross-sectional view of the pump of FIG. 1, as the plungerassembly reaches the top of an upstroke.

FIG. 6 is a cross-sectional view of the pump of FIG. 1, with the plungerassembly moving in a downwell direction in response to a release ofpressure introduced by the surface pumping unit to the fluid in thetubing string, and the application of hydrostatic pressure frombalancing fluid contained in the fluid conduit.

DETAILED DESCRIPTION OF THE EMBODIMENTS

Before describing selected embodiments of the present disclosure indetail, it is to be understood that the present invention is not limitedto the particular embodiments described herein. The disclosure anddescription herein is illustrative and explanatory of one or morepresently preferred embodiments and variations thereof, and it will beappreciated by those skilled in the art that various changes in thedesign, organization, order of operation, means of operation, equipmentstructures and location, methodology, and use of mechanical equivalentsmay be made without departing from the spirit of the invention.

As well, it should be understood that the drawings are intended toillustrate and plainly disclose presently preferred embodiments to oneof skill in the art, but are not intended to be manufacturing leveldrawings or renditions of final products, and may include simplifiedconceptual views as desired for easier and quicker understanding orexplanation. As well, the relative size and arrangement of thecomponents may differ from that shown and still operate within thespirit of the invention.

Moreover, it will be understood that various directions such as “upper,”“lower,” “bottom,” “top,” “left,” “right,” and so forth are made onlywith respect to explanation in conjunction with the drawings, and thatthe components may be oriented differently, for instance, duringtransportation and manufacturing as well as operation. Because manyvarying and different embodiments may be made within the scope of theconcepts herein taught, and because many modifications may be made inthe embodiments described herein, it is to be understood that thedetails herein are to be interpreted as illustrative and non-limiting.

Embodiments within the scope of the present disclosure relate,generally, to systems and methods usable for pumping fluids from a well.One disclosed embodiment of the pump eliminates costly repair andmaintenance of producing wells due to sucker rod separation byeliminating the use of rods and by connecting the pump to a secondsmaller tubing (i.e. conduit) string, which also enables ease ofinsertion and retrieval. In an embodiment, the pump can be inserted intoproduction tubing used throughout the petroleum industry and utilizingthe tubing packer (i.e. seating nipple) already present at the bottom ofmost such production tubing. The conduit also enables the formation of asecond fluid column, which balances fluid pressure in the productiontubing, which enables the actuation of the downhole pump byintermittently applying and removing pressure from the productiontubing.

Referring now to FIG. 1, a cross-sectional view of an embodiment of asubsurface pump (10) usable within the scope of the present disclosureis shown. The subsurface pump, as depicted, is mounted within a tubingstring (5) (e.g., production tubing) which extends to the surface (2) ofthe wellbore (4) within which the tubing string (5) is positioned. Atthe surface (2), the tubing string (5) can be fluidly connected to asurface pumping unit (not shown), which is usable to force fluids downthe tubing string (5), e.g., by applying pressure to the fluid in thetubing string (5) to actuate the subsurface pump (10). As furtherdepicted in FIG. 1, the pump includes an upper barrel (11), a lowerbarrel (12), and a plunger assembly (20), which includes an upperplunger (21), a lower plunger (22), and a connecting shaft (23)extending therebetween. The plunger assembly (20) is movably disposedwithin the upper and lower barrels (11, 12), as described in more detailbelow.

During typical operation, the pump (10) can be positioned toward thedownwell end of the tubing string (5), within the reservoir (3) area. Acasing may be inserted into the wellbore (4) to prevent the walls of thewellbore from collapsing. The wellbore (4) and the casing includeperforations formed in the side walls thereof to permit fluid to flowfrom a well production zone into the wellbore (4), such that a wellborefluid annulus (6), which surrounds the pump (10), can be filled withproduction fluid. The area of the wellbore fluid annulus (6), filledwith production fluids, will hereafter be referred to as the reservoir(3). It should be understood, however, that embodiments usable withinthe scope of the present disclosure could also be used within uncasedwellbores.

As depicted in FIGS. 1 and 3, the subsurface pump (10) includes a tubemounting section (30) at the lower end of the pump (10). The tubemounting section (30) can securely attach the pump (10) to a seatingnipple (35) formed and/or mounted in the lower end of the tubing string(5). The seating nipple (35) can be a standard type commonly used forrod pump installation. Thus, the subsurface pump (10) can replace asucker rod pump, typically used in a standard rod pump system, withoutrequiring removal and/or retrieval of the tubing string (5) forinstalling special seating nipples (35). The tube mounting section (30)can be configured to include rubber o-ring seals (32) or similar sealingmembers to prevent fluids from breaching the seal (e.g., bypassing thepump) when the tube mounting section (30) is engaged with acorresponding seating nipple (35). It should be understood that themanner of sealing the pump (10) against the seating nipple (35) caninclude any type, configuration, number, and/or combination of sealingelements, including elastomeric seals, metal-to-metal seal, or othertypes of sealing. FIG. 1 also depicts the tube mounting section (30)having a chamfered end (34), which aids insertion into the seatingnipple (35) by guiding the tube mounting section (30) into the engagedposition.

At the upwell end of the pump (10), FIG. 1 further depicts a fluidconduit (15) (e.g. a fluid passageway), which is connected to the pump(10) at the upwell end of the upper barrel (11). The fluid conduit (15),along with the tubing string (5), communicates fluids between thesurface (2) of the wellbore (4) and the pump (10). Specifically, thedepicted pumping system utilizes two fluid passageways from the surfaceof the well, one being the aforementioned tubing string (5) and thesecond being the fluid conduit (15) that contains a hydrostatic pressurebalancing fluid. FIG. 1 depicts the upper barrel (11) being adapted forconnecting to the fluid conduit (15), while production fluid flowsthrough the annulus (7), between the tubing string (5) and the conduit(15)—pump (10) assembly. The conduit (15) is positioned within thetubing string (5) and is connected to a surface source of balancingfluid, which is discussed in further detail below. The tubing string (5)can be connected to a surface pumping unit (not shown), such as ahydraulic pump having a timed cycle for controlling the upstroke anddownstroke of plunger assembly (20). The combination of the fluidconduit (15) and the fluid contained therein eliminates the need for useof a downhole gas chamber, normally required to push the productionfluid to the surface (2). It should be understood that the manner inwhich the fluid conduit (15) is connected to the upper barrel (11) caninclude any means known in the art. For example, the two components canbe engaged to one another using a threaded connection, by welding, bycrimping, using a forced or interference fit, using one or morefasteners, or by using any other means of attachment known in the art.

As shown, the downwell end of the pump (10) includes a lower barrel(12). As depicted in FIGS. 1 and 3, the inside diameter of the lowerbarrel is preferably smaller than the inside diameter of the upperbarrel (11). At the downwell end of the pump, an inlet port (33) islocated, which communicates production fluid from the reservoir (3) intothe lower barrel (12). A standing check valve (42) is shown positionedat the inlet port (33), below the plunger assembly (20), and providesselective fluid communication between the production fluid in thereservoir (3) and the lower barrel (12). As explained in more detailbelow, the standing check valve (42) allows production fluid from thereservoir (3) to flow into the lower barrel (12) and prevents the flowof fluid from within the lower barrel (12), outwardly, into thereservoir (3).

FIGS. 1 and 2 depict a transition portion (14) located between the upperbarrel (11) and the lower barrel (12), which allows the larger diameterupper barrel (11) to connect to a smaller diameter lower barrel (12).The transition section (14) can contain a plurality of fluid ports orannular ports (13), which allow fluid communication between the tubingstring annulus (7) and the central cavity (53), which is a volumetricarea that will be described in more detail below. It should beunderstood that while the annular ports (13) are shown within thetransition portion (14) of the upper barrel, such ports are preferablylocated below the lowermost position of the upper plunger (21) and abovethe uppermost position of the lower plunger (22). The annular ports (13)can provide fluid communication between the production fluid in thetubing string annulus (7) and the central cavity (53), allowing thepressurized fluid to enter the pump (10), to lift the plunger assembly(20), and to exit the pump (10) as the plunger assembly (20) is forceddown.

Referring specifically to the plunger assembly (20), FIG. 1 depicts aplunger assembly comprising an upper plunger (21), a shaft (23), a lowerplunger (22), and a traveling valve (41). The plunger assembly (20) ismovably positioned within the pump (10). Specifically, the upper plunger(21) moves within the space inside the upper barrel (11), and the lowerplunger (22) moves within the space inside the lower barrel (12). Theupper and lower plungers (21, 22) are connected by a shaft (23). Theplunger assembly (20) may be of unitary construction or of variousconnected assemblies, and may be formed from any suitable material(e.g., metal or a metal alloy), preferably a material that is corrosionresistant, especially against salt water.

As further depicted in FIG. 1, several volumetric areas exist within thepump (10). The area within the upper barrel (11), formed upwell of theupper plunger (21) and below the fluid conduit (15), is termed the uppercavity (51). The area within the lower barrel (12), formed downwell ofthe lower plunger (22) and above the standing check valve (42), istermed the lower cavity. The area within the upper and lower barrels(11, 12), formed between the upper plunger (21) and the traveling checkvalve (41) is termed the central cavity (53). As the plunger assembly(20) moves upwell and downwell within the pump (10), these volumetricareas are simultaneously enlarged or reduced.

Referring again to the plunger assembly (20) depicted in FIGS. 1 and 2,in an embodiment, the upper plunger (21), located on the upwell end ofthe plunger assembly (20), can be a solid cylindrical member, and caninclude sealing elements on the outside surface to prevent fluids frombreaching the seal during pump operation. Usable sealing means aredescribed in more detail below.

The lower plunger (22), depicted in FIGS. 1 and 3, can include acylindrical member located at the downwell end of the plunger assembly(20). Unlike the upper plunger (21), the lower plunger (22) isconfigured to allow production fluids to bypass the lower plunger (22)at specific stages of pump operation. Consequently, the lower plunger(22) may have a fluid passageway through at least a portion of itslength. A traveling check valve (41) is shown at the bottom of the lowerplunger (22) for providing selective fluid communication between thelower cavity (52) and the central cavity, (53) through the fluidpassageway of the lower plunger (22). Specifically, the traveling valve(41) is a flow control valve, which prevents fluid flow in the downwelldirection and allows fluid to pass in the upwell direction, as theplunger assembly (20) is moving in the downwell direction. The travelingcheck valve (41) can be of any type, including a valve having a gravityactuated flow restricting element, such as a ball (as depicted in FIG.1), such that gravity can retain the flow restricting element on thevalve seat. The traveling check valve (41) could also include a springassisted check valve, wherein a spring retains the flow restrictingelement on the valve seat, or other types of valves known in the art.

Embodiments of the plunger assembly (20), which are disclosed above,require little to no significant compression forces to be applied to theshaft (23) during the operation of the pump (10). Therefore, the shaft(23) in the present pump can be longer than the rods in conventionalsubsurface pumps, enabling an increased stroke and pumping capacity.During the down stroke, the production fluid flows through the travelingcheck valve (41) to offer little resistance to the lower plunger (22).During the up stroke, the traveling check valve (41) closes, preventingfluid flow through the fluid passageway of the lower plunger (22),however, the shaft (23) is in tension during this stage. In theembodiment depicted, the stroke length is 24 feet, however, otherembodiments, having strokes greater or less than 24 feet are alsopossible.

Generally, the outside diameter of the upper and lower plungers (21, 22)must properly mate with the inside diameters of the correspondingbarrels (11, 12), the relative fit between the plungers (21, 22) andbarrels (11, 12) being sufficiently close to facilitate a formation of afluid seal between the two sets of components, but at the same time toallow the plungers (21, 22) to move freely within the barrels (11, 12).The lengths of the plungers (21, 22) can vary depending on the overalllength and stroke length of the pump (10).

As it is desirable that the pump (10) be inserted into tubing string (5)and, at the same time, maintain the largest possible internal volume,embodiments of the present pump can include barrels (11, 12) having wallthicknesses less than that of conventional downwell pumps. The thinwalls of the pump (10) can be more susceptible to high hydrostaticpressures associated with deep wells, and can undergo significantstrains when lowered to high depths. At such depths, the barrel (11, 12)walls may be compressed and the inside diameter of the pump (10)narrowed to a point where contact and/or friction between the plungers(21, 22) and barrels (11, 12) causes the plungers (21, 22) to becomeunable to reciprocate within the barrels (11, 12). To prevent suchseizure, the outside diameters of the plungers (21, 22) may be sized tobe significantly smaller than the inside diameters of the barrels (11,12). However, incorporating a large clearance (25) in the fit, betweenthe upper barrel (11) and the upper plunger (21), can result in fluidsleaking between the upper and central cavities (51, 53).

To solve this problem, the outside surface of the plungers (21, 22) canbe configured to include sealing elements to prevent such fluids fromleaking during pump operation. Sealing elements such as lip seals, cups,and/or sealing rings, and other similar sealing elements, can be used.For example, metal sealing rings (26) shown in FIG. 2, may be providedas a single piece, as multiple pieces, or spring backed. For optimaloperation, the seals can be sized to close the space between the upperbarrel (11) and the upper plunger (21) and possess the ability to adjustin height as the upper plunger (21) shifts positions relative to theupper barrel (21) during operation. This can be achieved, for example byincorporating sealing elements, comprising flexible material, which arethen compressed as the upper plunger moves relative to the barrel walls.Another example is a sealing ring (26) that floats in a deep groovehaving a smaller diameter than the inside diameter of the sealing ring(26). As depicted in FIG. 2, the sealing rings (26) are pushed by theupper barrel (11) wall into the grooves on one side of the upper plunger(21) and extend out of the groove on the other side, as the upperplunger (21) moves radially, within the upper barrel (11), relative tothe longitudinal axis of the upper barrel (11). In still anotherembodiment, the sealing ring (26) may be centered about the upper barrel(11) by a spring. It should be understood that the sealing meansdescribed can include any type and/or combination of sealing elementsand any arrangement thereof, to optimize performance of the pump. Itshould be understood that either the upper plunger (21), or bothplungers (21, 22), may include the clearance and sealing configuration,as described above. In an embodiment, the lower plunger can containlittle to no clearance and no additional sealing elements, and can relyonly on metal-to-metal sealing between the lower plunger (22) and lowerbarrel (12).

Several significant improvements can be attributed to the novelconfiguration of the pump (10) as disclosed. For example, embodiments ofthe present subsurface pump (10) can allow for a stroke that may be 24feet in length or longer. Due to such long strokes, the pump cyclefrequency is significantly slowed when compared to conventional pumps,resulting in reduced wear and extending the life of the pump.Furthermore, as shown in FIGS. 1 and 2, the length and the thin walls ofthe pump barrels (11, 12), the large clearance fit (25) between theupper barrel (11) and the upper plunger (21), as well as the long lengthof the plungers (21, 22), enable the pump (10) to flex and withstandsignificant bending in the wellbore while maintaining fluid sealing,which further allows the pump (10) to be lowered through tight cornersand to properly operate to pump fluids, while positioned within deviatedwells.

As the thin barrel walls require less lateral forces to cause bending,the pump (10) flexes more easily with less internal stresses (e.g.tension, compression, shear, etc.) within the barrel walls duringlowering and retrieval into or from a wellbore. As a result, the barrelwalls experience lesser internal strains and therefore a lesser chanceof permanent deformation in the pump structure. Also, the largeclearance (25) in the fit between the barrel walls and the upper plunger(21) can result in a small range of motion (e.g., “play”) between thetwo components, which can allow the barrels (11, 12) to bendsubstantially without interfering with the upper plunger (21).Furthermore, the length of the upper plunger (21) also enables the pump(10) to flex without resulting in high local forces being applied to thebarrel walls, which can result in permanent deformation in the pumpstructure. During pump lowering through the tubing string (5) or duringoperation, especially in a deviated wellbore, contact between the upperplunger (21) and the upper barrel (11) walls can result. Such contactcan introduce high forces and stresses in the upper barrel (11) wallsthat can cause permanent deformation thereof. A longer plunger (21)contains a larger surface area that contacts the walls of the upperbarrel (11), which results in a greater distribution of lateral orbending forces between the two parts along a larger surface area ofcontact. Greater distribution of contact forces result in smallerstresses between the upper barrel (11) and upper plunger (21),decreasing the chances of permanent damage to the pump (10). Lastly, alarger surface area of contact between the upper plunger (21) and upperbarrel (11) also allows for improved sealing, which can prevent fluidsfrom leaking between the two parts. Larger surface area between theupper barrel (11) and the upper plunger (21) result in increased sealingarea, which in turn results in a lesser amount of fluids leaking betweenthe two parts. Larger surface area between the two components alsoprovides more space for additional sealing elements, which improve theability to prevent fluid leakage. In the embodiment depicted, eachplunger (21, 22) is two feet in length, though other lengths are usablein other embodiments.

Referring again to FIG. 1, in a common oilfield application, the pump(10) would be connected to the bottom of a tubing string (5), within thereservoir (3) fluid to be produced. A pressure source, such as ahydraulic pump (not shown), would be connected at the surface to thetubing string (5) so as to selectively apply pressure into the tubingstring (5), which actuates the downhole pump (10). The conduit (15) canbe positioned within the tubing string (5) to allow communication of thebalancing fluid with the upper cavity (51). A balancing fluid, which maycomprise fluids such as salt water or other fluid, is contained withinthe upper cavity (51) and the conduit (15). Typically, the balancingfluid inside the upper cavity (51) is not externally pressurized andrelies upon the hydrostatic column pressure, determined by the height ofthe fluid in the upper cavity (51) and the conduit (15) between the pump(10) and the surface of the well (2). When the plunger assembly (20) isin the lowest (e.g., downwell) position, there is a substantial balanceof the hydrostatic pressures in the tubing string and the conduit.

During the upstroke phase of pump operation, the pressure of thebalancing fluid column is exceeded by the pressure in the tubing string(5), as generated by the surface pump (not shown). Specifically,production fluid is communicated into the central cavity (53) throughthe annular ports (13), and the balancing fluid is pushed out of theupper cavity (51) and upwell, into the conduit (15). As the fluid in theconduit (15) rises above the surface (2), the pressure of the balancingfluid at the pump (10) raises, and an imbalance between the hydrostaticpressure in the central cavity (53) and the hydrostatic pressure in theupper cavity (51) is formed. As the plunger assembly (20) reaches itsupper most position, the surface pump is disconnected from the tubingstring (5) and the pressure generated by the pump is released. As thehydrostatic pressure of the fluid column in the fluid conduit (15) isgreater than the hydrostatic pressure of the fluid column in the tubingstring (5), the plunger assembly (20) is forced in the downwelldirection. The upper plunger (21) forms a barrier between the productionfluid in the central cavity (51) and the balancing fluid in the uppercavity (53); however, some transfer of fluid between the two cavities(51, 53) may occur as some fluids may leak past the upper plunger (21).As the plunger assembly (20) moves upwell and downwell within the pump(10), it draws production fluids into the lower barrel (12) from thereservoir (3) on the upstroke and forces it out into the tubing string(5) on the downstroke.

A more detailed operation of the pump system is described below. Thisprocess, as shown in FIGS. 4 through 6 is discussed below, can berepeated for extended periods of time to produce a well.

FIG. 1 shows the plunger assembly (20) in its lowermost position withthe well fluid and the balancing fluid being static. When the pump ispositioned as shown in FIG. 1, only hydrostatic pressure is presentabout the upper plunger (21). The standing valve and the traveling valveare both closed and no fluid communication takes place.

FIG. 4 shows the plunger assembly (20) moving upward. As the surfaceunit (not shown) is activated, fluid is pumped down the tubing string(5) (as shown by the arrows) into the annulus (7) surrounding the upperbarrel (11), and through the annular ports (13) ports into the centralcavity (53), between upper and lower plungers (21, 22); moving theplunger assembly (20) upward, due to the larger diameter of the upperplunger (21) as opposed to the diameter of the lower plunger (22). Atsubstantially the same time, the balancing fluid is forced out of theupper cavity (51) and upward into the conduit (as shown by the arrows).The traveling valve (41) remains closed, and the standing valve (42)opens to allow production fluid (e.g., hydrocarbons) from the reservoir(3) to be drawn through the inlet port (33), and into the lower barrel(12) (as shown by the arrows).

FIG. 5 shows the plunger assembly (20) at the uppermost part of theupstroke. The surface unit (not shown) is still pressurizing the tubingstring (5), maintaining the position. The upper barrel, which nowcomprises most of the central cavity, is filled with the pressurizedfluid from the tubing string (5), while the lower barrel (12), which nowcomprises most of the lower cavity (52), is filled with fluid drawn fromthe reservoir (3). The fluid from the upper cavity (51, shown in FIGS. 4and 6) has been forced upwell into the fluid conduit (15). Both thetraveling valve (41) and the standing valve (42) are closed.

FIG. 6 shows a plunger assembly (20) moving in a downwell direction inresponse to pressure from the balancing fluid against the upper plunger(21). After the plunger assembly (20) reaches the top of its strokewithin the pump (10), as depicted in FIG. 5, the surface pump unit (notshown) is disconnected from the tubing string (5), releasing thepressure that it generated. The hydrostatic pressure of the fluid columnin the fluid conduit (15) is now greater than the hydrostatic pressureof the fluid column in the tubing string (5). As a result, the plunger(20) assembly is forced in a downwell direction by the pressuredifferential about the upper plunger (21). The standing valve (42) isclosed, preventing fluid in lower cavity (52) from escaping into thereservoir (3). At the same time, the traveling valve (41) opens,allowing fluid to communicate from the lower cavity (52) into thecentral cavity (53). The fluid in the central cavity (53) is then forcedout of the pump (10) into the annulus (7) of the tubing string (5)through the annular ports (13) (as shown by the arrows) to be producedat the surface.

FIG. 1 shows the plunger assembly (20) at the bottom of the downstroke.Once the upper plunger (21) makes contact with the bottom of the upperbarrel (11), the cycle can start again, as described above.

While various embodiments usable within the scope of the presentdisclosure have been described with emphasis, it should be understoodthat within the scope of the appended claims, the present invention canbe practiced other than as specifically described herein.

What is claimed is:
 1. A pump assembly positioned within and in fluidcommunication with production tubing extending between a subsurfacefluid reservoir and a well surface, the pump assembly comprising: anupper barrel connected to a fluid conduit that extends between the upperbarrel and the well surface; a lower barrel connected to the upperbarrel and in fluid communication with the subsurface fluid reservoir;and a plunger assembly comprising: an upper plunger movably disposedwithin the upper barrel; and a lower plunger connected by a shaft to theupper plunger and movably disposed within the lower barrel, wherein theplunger assembly draws fluid from the subsurface fluid reservoir intothe pump assembly and pushes fluid out of the pump assembly into theproduction tubing in response to fluid pressure changes within theproduction tubing.
 2. The pump assembly of claim 1, wherein the fluidconduit is filled with balancing fluid, wherein the fluid within theproduction tubing moves the plunger in a first direction as fluidpressure within the production tubing increases, and wherein thebalancing fluid in the fluid conduit moves the plunger in a seconddirection as fluid pressure within the production tubing is released. 3.The pump assembly of claim 1, further comprising sealing elementslocated on the upper plunger, wherein the sealing elements allow theupper plunger to move laterally within the upper barrel whilemaintaining sealing action.
 4. The pump assembly of claim 1, wherein theupper plunger has an outside diameter that is sized to permit axialmovement within the upper barrel when the upper barrel is compressed orbent by an external force.
 5. The pump assembly of claim 1, wherein theplunger assembly moves at least 18 feet or more within the pumpassembly.
 6. The pump assembly of claim 1, wherein the upper plunger isgreater than 20 inches in length.
 7. A pump assembly for pumping fluidfrom a subsurface fluid reservoir comprising: an upper barrel connectedto a lower barrel and a fluid conduit, wherein the lower barrel is influid communication with the subsurface fluid reservoir, and wherein thefluid conduit extends from the upper barrel to a surface of a well; anda plunger assembly movably disposed within the upper barrel and thelower barrel, wherein fluid pressure within a production tubing externalto the fluid conduit moves the plunger assembly in a first direction todraw fluid into the lower barrel, wherein fluid pressure within thefluid conduit moves the plunger assembly in a second direction to pushfluid into the production tubing, and wherein the pump assembly preventsfluid flow from the production tubing into the fluid reservoir.
 8. Thepump assembly of claim 7, wherein the plunger assembly furthercomprises: a lower plunger movable within the lower barrel; and an upperplunger movable within the upper barrel, wherein the upper plunger hasan outside diameter that is smaller than an inside diameter of the upperbarrel for permitting axial movement of the upper plunger within theupper barrel when the upper barrel is compressed or bent by an externalforce, and wherein sealing elements on the upper plunger prevent fluidflow through an annulus between the upper barrel and the upper plunger.9. The pump assembly of claim 8, wherein the pump assembly is configuredfor insertion into the production tubing, wherein the pump assemblyfurther comprises a mating area configured for attachment to theproduction tubing, and wherein the mating area prevents fluidcommunication between the production tubing and the fluid reservoirthrough an annular space between the production tubing and the pumpassembly.
 10. The pump assembly of claim 8, wherein the sealing elementscomprise piston ring seals, lip-seals, cup seals, or combinationsthereof, and wherein the sealing elements permit lateral movement of theupper plunger within the upper barrel.
 11. The pump assembly of claim 8,wherein the sealing elements permit axial movement of the upper plungerwithin the upper barrel when the upper barrel is compressed or bent byan external force.
 12. The pump assembly of claim 8, wherein the upperplunger is greater than 20 inches in length.
 13. The pump assembly ofclaim 8, wherein the upper and lower plungers are configured to movemore than 18 feet within the upper and lower barrels respectively.
 14. Apump assembly, comprising an upper barrel connected to a lower barrel,wherein the upper barrel is fluidly connected to the lower barrel, andwherein the upper barrel is fluidly connectable to a fluid conduit; thelower barrel fluidly connectable to a fluid reservoir; a plungerassembly comprising an upper plunger movable within the upper barrel anda lower plunger movable within the lower barrel, wherein the upperplunger and the lower plunger are connected, wherein the plungerassembly is movable in a first direction to draw fluid from the fluidreservoir into the lower barrel responsive to a pressure increaseexternal to the pump assembly, and wherein the plunger assembly ismovable in a second direction to push fluid out of the pump assemblyresponsive to a pressure decrease external to the pump assembly.
 15. Thepump assembly of claim 14, wherein the pump assembly is configured forinsertion into a production tubing, wherein the pump assembly furthercomprises a mating area configured for attachment to the productiontubing, and wherein the mating area prevents fluid communication betweenthe production tubing and the fluid reservoir through an annular spacebetween the production tubing and the pump assembly.
 16. The pumpassembly of claim 14, wherein the pump assembly further comprises: acheck valve, wherein the check valve prevents fluid from flowing fromthe lower barrel to the fluid reservoir.
 17. The pump assembly of claim14, wherein the upper plunger has an outside diameter that is smallerthan an inside diameter of the upper barrel for permitting axialmovement of the upper plunger within the upper barrel when the upperbarrel is compressed or bent by an external force, and wherein the upperplunger comprises sealing elements which seal an annular area betweenthe upper plunger and the upper barrel.
 18. The pump assembly of claim17, wherein the sealing elements comprise piston ring seals, lip-seals,cup seals, or combinations thereof, and wherein the sealing elementspermit axial movement of the upper plunger within the upper barrel whenthe upper barrel is compressed or bent by an external force
 19. The pumpassembly of claim 14, wherein the upper plunger is greater than or equalto 20 inches in length.
 20. The pump assembly of claim 14, wherein theupper and lower plungers are configured to move at least 18 feet or morewithin the upper and lower barrels respectively.